U.S. patent number 5,417,286 [Application Number 08/174,303] was granted by the patent office on 1995-05-23 for method for enhancing the recovery of methane from a solid carbonaceous subterranean formation.
This patent grant is currently assigned to Amoco Corporation. Invention is credited to Ian D. Palmer, Dan Yee.
United States Patent |
5,417,286 |
Palmer , et al. |
May 23, 1995 |
**Please see images for:
( Certificate of Correction ) ** |
Method for enhancing the recovery of methane from a solid
carbonaceous subterranean formation
Abstract
A method for improving the recovery of methane from a solid
carbonaceous subterranean formation penetrated by a wellbore, the
method comprising the steps of introducing a first fluid into the
formation which sorbs to the formation, allowing at least a portion
of the first fluid to sorb to the formation, introducing a
chemically different second fluid into the formation at a pressure
higher than the parting pressure of the formation, relieving
pressure within the formation to produce shear failure within the
formation, and repeating the introduction of second fluid and the
relieving of pressure until a desired permeability of the formation
is obtained.
Inventors: |
Palmer; Ian D. (Tulsa, OK),
Yee; Dan (Tulsa, OK) |
Assignee: |
Amoco Corporation (Chicago,
IL)
|
Family
ID: |
22635675 |
Appl.
No.: |
08/174,303 |
Filed: |
December 29, 1993 |
Current U.S.
Class: |
166/308.1;
166/305.1 |
Current CPC
Class: |
E21B
43/006 (20130101); E21B 43/26 (20130101) |
Current International
Class: |
E21B
43/26 (20060101); E21B 43/00 (20060101); E21B
43/25 (20060101); E21B 043/26 () |
Field of
Search: |
;166/250,308,305.1 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
Other References
R S. Metcalf, D. Yee, J. P. Seidle, and R. Puri, "Review of
Research Efforts in Coalbed Methane Recovery", SPE 23025 (1991).
.
A. V. Astakhov and D. L. Shirochin, "Capillary-Like Condensation of
Sorbed Gases in Coals", Fuel, vol. 70, pp. 51-56 (Jan. 1991). .
B. D. Hughes and T. L. Logan, "How to Design a Coalbed Methane
Well", Petroleum Engineer International, pp. 16-20 (May 1990).
.
Carl L. Schuster, "Detection Within the Wellbore of Seismic Signals
Created by Hydraulic Fracturing", SPE 7448 (1978). .
Ralph W. Veach, Jr., Zissis A. Mosachovidis and C. Robert Fast, "An
Overview of Hydraulic Fracturing", Recent Advances in Hydraulic
Fracturing, vol. 12, Chapter 1, pp. 1-38, S.P.E. Monograph Series
(1989). .
N. R. Warpinski and Michael Berry Smith, "Rock Mechanics and
Fracture Geometry," Recent Advances in Hydraulic Fracturing, vol.
12, Chapter 3, pp. 57-80, S.P.E. Monograph Series (1989). .
Arfon H. Jones, et al., "A Review of the Physical and Mechanical
Properties of Coal with Implications for Coal-Bed Methane Well
Completion and Production", pp. 169-181, Coal-Bed Methane, a
publication of the Rocky Mountain Association of Geologists (1988).
.
H. H. Abass et al., "Experimental Observations of Hydraulic
Fracture Propagation Through Coal Blocks", SPE 21289 (Nov. 1990).
.
B. W. McDaniel, "Benefits and Problems of Minifrac Applications in
Coalbed Methane Wells", pp. 103-1 through 103-16, Paper No. CIM/SPE
90-103, a publication of the Petroleum Society of CIM and the
Society of Petroleum Engineers (1990). .
T. L. Logan et al., "Optimizing and Evaluation of Open-Hole Cavity
Completion Techniques for Coal Gas Wells", Proceedings of the 1993
International Coalbed Methane Symposium, The University of
Alabama/Tuscaloosa, 9346, (May 1993). .
S. D. Spafford et al., "Remedial Stimulation of Coalbed Methane
Wells: A Case Study of Rock Creek Wells", Proceedings of the 1993
International Coalbed Methane Symposium, The University of
Alabama/Tuscaloosa, 9374, (May 1993). .
T. L. Logan et al., "Methane from Coal Seams Research", Quarterly
Review of Methane from Coal Seam Technology, pp. 6-12, published by
the Gas Research Institute, (Apr. 1993). .
S. R. Daines, "Prediction of Fracture Pressures for Wildcat Wells",
Journal of Petroleum Technology, pp. 863-872, (Apr. 1982). .
I. D. Palmer et al., "Coalbed Methane Well Completions and
Stimulations", Chapter 14, pp. 303.sub.]339, Hydrocarbons from
Coal, published by the American Association of Petroleum Geologists
(1993). .
R. G. Jeffrey et al., "Small-Scale Hydraulic Fracturing and
Mineback Experiments in Coal Seams", Proceedings of the 1993
International Coalbed Methane Symposium, The University of
Alabama/Tuscaloosa, 9330, (May 1993). .
H. Morales et al., "Analysis of Coalbed Hydraulic Fracturing
Behavior in the Bowen Basin (Australia)", Proceedings of the 1993
International Coalbed Methane Symposium, The University of
Alabama/Tuscaloosa, 9349, (May 1993). .
I. D. Palmer et al., "Sandless Water Fracture Treatments in Warrior
Basin Coalbeds", Proceedings of the 1993 International Coalbed
Methane Symposium, The University of Alabama/Tuscaloosa, 9355, (May
1993). .
S. D. Spafford et al., "Remedial Stimulation of Coalbed Methane
Wells: A Case Study of Rock Creek Wells", Proceedings of the 1993
International Coalbed Methane Symposium, The University of
Alabama/Tuscaloosa, 9374, (May 1993). .
M. Khodaverdian et al., "Cavity Completions: A Study of Mechanisms
and Applicability", Proceedings of the 1993 International Coalbed
Methane Symposium, The University of Alabama/Tuscaloosa, 9336, (May
1993). .
S. W. Lambert et al., "Warrior Basin Drilling, Stimulation
Covered", Oil & Gas Journal, pp. 87-92, (Nov. 13, 1989). .
T. L. Logan et al., "Hydraulic Fracture Stimulation and Openhole
Testing of a Deeply Buried Coal Seam in the Piceance Basin,
Colorado", Society of Petroleum Engineers, SPE 15251 (1986). .
I. D. Palmer et al., "Openhole Cavity Completions in Coalbed
Methane Wells in the San Juan Basin", Society of Petroleum
Engineers, SPE 24906, (1992). .
I. D. Palmer, "Review of Coalbed Methane Well Stimulation", Society
of Petroleum Engineers, SPE 22395, (1992)..
|
Primary Examiner: Suchfield; George A.
Attorney, Agent or Firm: Wakefield; Charles P. Kretchmer;
Richard A.
Claims
We claim:
1. A method for improving the recovery of methane from a solid
carbonaceous subterranean formation penetrated by a wellbore, the
method comprising the steps of:
a) introducing a first fluid into the solid carbonaceous
subterranean formation which sorbs to the solid carbonaceous
subterranean formation;
b) allowing at least a portion of the first fluid to sorb the solid
carbonaceous subterranean formation;
c) introducing a chemically different second fluid into the solid
carbonaceous subterranean formation at a pressure higher than the
parting pressure of the solid carbonaceous subterranean
formation;
d) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean formation; and
e) repeating steps c) through d) until a desired permeability of
the solid carbonaceous subterranean formation is obtained.
2. The method of claim 1, further comprising the step of removing
fines from the wellbore which were produced during step d).
3. The method of claim 2, wherein steps c) through d) are repeated
until the amount of fines produced decreases to substantially
zero.
4. The method of claim 1, wherein the first fluid is selected from
the group consisting of carbon dioxide, xenon, argon, neon,
hydrogen sulfide, ammonia, methane, ethane, propane, butane, air,
hydrogen, carbon monoxide, nitrogen, flue gas and combinations
thereof.
5. The method of claim 4, wherein the second fluid is selected from
the group consisting of nitrogen, carbon dioxide, air, methane,
flue gas, and combinations thereof.
6. The method of claim 4, wherein the second fluid is selected from
the group consisting of water, foamed water, cross-linked gel,
foam, foamed cross-linked gel, foamed linear gel and combinations
thereof.
7. The method of claim 6, further comprising repeating steps a)
through b).
8. The method of claim 7, wherein steps a) through b) are repeated
every time steps c) through d) are repeated.
9. The method of claim 6, wherein the first fluid is injected at a
pressure higher than the parting pressure of the solid carbonaceous
subterranean formation.
10. The method of claim 1, wherein the pressure relieved in step d)
is relieved from at least about 100 to 1000 p.s.i. above the
parting pressure of the formation to about 200 to 600 p.s.i. below
a reservoir pressure of the formation within 15 minutes to one
hour.
11. The method of claim 1, wherein the second fluid is selected
from the group including water, foamed water, cross-linked gel,
foam, foamed cross-linked gels, foamed linear gel, and combinations
thereof.
12. The method of claim 1, wherein the second fluid is selected
from the group consisting of nitrogen, carbon dioxide, air,
methane, flue gas, and combinations thereof.
13. The method of claim 1, wherein the first fluid is injected at a
pressure higher than the parting pressure of the solid carbonaceous
subterranean formation.
14. The method of claim 1 further comprising repeating steps a) and
b).
15. The method of claim 1, wherein the solid carbonaceous
subterranean formation comprises a coalbed.
16. The method of claim 1, wherein a section of the wellbore which
penetrates the formation forms an open-hole interval which has
walls cut into a shape which will intensify the stresses acting on
the open-hole interval.
17. The method of claim 1, further comprising:
f) recovering methane from the formation through the wellbore.
18. A method for improving the recovery of methane from a solid
carbonaceous subterranean formation penetrated by a wellbore, the
method comprising the steps of:
a) introducing a fluid into the solid carbonaceous subterranean
formation which sorbs to the solid carbonaceous subterranean
formation at a pressure above the parting pressure of the
formation;
b) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean formation; and
c) repeating steps a) through b) at least until a calculated rate
of change of the Darting pressure from the second to last
introduction of fluid to the last introduction of fluid is less
than one half the calculated rate of change of the parting pressure
from the third to last introduction of fluid to the second to last
introduction of fluid.
19. The method of claim 18, wherein steps a) through b) are
repeated until a rate of change of the parting pressure from cycle
to subsequent cycle approaches a value of near zero.
20. The method of claim 18, wherein the fluid is selected from the
group consisting of nitrogen, carbon dioxide, methane, carbon
monoxide, hydrogen, flue gas and mixtures thereof.
21. The method of claim 18, wherein the introduced fluid is
maintained in the solid carbonaceous subterranean formation to
enhance the sorption of the fluid to a carbonaceous matrix of the
formation.
22. The method of claim 18, wherein the fluid comprises at least
about 80% by volume nitrogen.
23. The method of claim 18, wherein the fluid comprises at least
about 80% by volume carbon dioxide.
24. The method of claim 18, wherein the fluid comprises at least 5%
by volume methane.
25. The method of claim 18, wherein the wellbore has wellbore
control equipment and the pressure is relieved at a rate
essentially equivalent to a maximum flow rate permitted by the
wellbore and wellbore control equipment.
26. The method of claim 18, wherein the pressure relieved in step
b) is relieved from at least about 100 to 1000 p.s.i. above the
parting pressure of the formation to about 200 to 600 p.s.i. below
a reservoir pressure of the formation within 15 minutes to one
hour.
27. The method of claim 18, further comprising introducing a second
fluid into the formation at a pressure below the parting pressure
of the formation.
28. The method of claim 27, wherein the second fluid comprises
carbon dioxide and the fluid introduced above the parting pressure
comprises nitrogen.
29. The method of claim 18, wherein the solid carbonaceous
subterranean formation comprises a coalbed.
30. The method of claim 18, wherein a section of the wellbore which
penetrates the solid carbonaceous subterranean formation is
completed using a cased-hole technique.
31. The method of claim 18, further comprising:
d) recovering methane from the formation through the wellbore.
32. A method for improving the recovery of methane from a solid
carbonaceous subterranean formation penetrated by a wellbore having
wellbore control equipment, capable of regulating the rate of fluid
flow from the wellbore, the method comprising the steps of:
a) introducing a fluid into the solid carbonaceous subterranean
formation which sorbs to the solid carbonaceous subterranean
formation at a pressure above the parting pressure of the
formation;
b) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean formation; and
c) repeating steps a) through b) at least until a calculated rate
of change of the apparent closure pressure from the second to
introduction of fluid to the last introduction of fluid is less
than one half the calculated rate of change of the apparent closure
pressure from the third to last introduction of fluid to the second
to last introduction of fluid.
33. The method of claim 32, wherein steps a) through b) are
repeated until a rate of change of the apparent closure pressure
from cycle to subsequent cycle approaches a value of near zero.
34. The method of claim 32, wherein the fluid comprises at least
80% by volume nitrogen.
35. The method of claim 32, wherein the pressure is relieved at a
rate essentially equivalent to a maximum flow rate permitted by the
wellbore and wellbore control equipment.
36. The method of claim 32, wherein the pressure relieved in step
b) is relieved from at least about 100 to 1000 p.s.i. above the
parting pressure of the formation to about 200 to 600 p.s.i. below
a reservoir pressure of the formation within 15 minutes to one
hour.
37. The method of claim 32, wherein a section of the wellbore which
penetrates the solid carbonaceous subterranean formation is
completed using a cased-hole technique.
38. The method of claim 32, wherein the fluid introduced above the
parting pressure comprises at least 80% by volume nitrogen and the
method further comprises:
d) introducing a second fluid, comprising carbon dioxide, into the
formation at a pressure below the parting pressure of the
formation.
39. The method of claim 32, further comprising:
d) recovering methane from the formation through the wellbore.
Description
FIELD OF THE INVENTION
This invention is directed to methods for increasing the rate of
recovery of methane from a solid carbonaceous subterranean
formation, and more specifically, to methods which increase the
rate of recovery by increasing the permeability of the
formation.
BACKGROUND OF THE INVENTION
Solid carbonaceous subterranean formations contain significant
quantities of natural gas. This natural gas is composed primarily
of methane. The majority of the methane is sorbed onto the
carbonaceous matrix of the formation and must be desorbed from the
matrix and transferred to a wellbore in order to be recovered. The
rate of recovery at the wellbore typically depends on the gas flow
rate through the solid carbonaceous subterranean formation. The gas
flow rate through a solid carbonaceous subterranean formation is
affected by many factors including the matrix porosity of the
formation, the system of fractures within the formation, and the
stress within the carbonaceous matrix which comprises the solid
carbonaceous subterranean formation.
An unstimulated solid carbonaceous subterranean formation has a
natural system of fractures, the smaller and most common ones being
referred to as "cleats" or collectively as a "cleat system". To
reach the wellbore, the methane must desorb from a sorption site
within the matrix and diffuse through the matrix to the cleat
system. The gas then passes through the cleat system to the
wellbore.
The cleat system communicating with a production well often does
not provide for an acceptable methane recovery rate. In general,
solid carbonaceous subterranean formations require stimulation to
enhance the recovery of methane from the formation. Various
techniques have been developed to stimulate solid carbonaceous
subterranean formations and thereby enhance the rate of recovery of
methane from these formations. These techniques typically attempt
to enhance the desorption of methane from the carbonaceous matrix
of the formation and/or to enhance the permeability of the
formation.
One example of a technique for stimulating the production of
methane from a solid carbonaceous subterranean formation is to
complete the production wellbore with an open-hole cavity. First, a
wellbore is drilled to a location above the solid carbonaceous
subterranean formation. The wellbore is cased and the casing is
cemented in place using a conventional drilling rig. A modified
drilling rig is then used to drill an "open-hole" interval within
the formation. An open-hole interval is an interval within the
solid carbonaceous subterranean formation which has no casing set.
A metal liner, which has holes, may be placed in the open-hole
interval if desired. The open-hole interval can be completed by
various methods. One method utilizes an injection/blowdown cycle to
create a cavity within the open-hole interval. In this method, air
is injected into the open-hole interval and then released rapidly
through a surface valve. The procedure is repeated until a suitable
cavity has been created. During the procedure, a small amount of
water can be added to selected air injections to reduce-the
potential for spontaneous combustion of the carbonaceous material
of the formation.
A limitation of this technique is that its effectiveness in
efficiently increasing methane recovery is mainly limited to
formations where formation pressure and permeability are high, such
as in the "fairway" zone of the San Juan Basin located in northern
New Mexico and southwestern Colorado.
Gel and foam fracture treatments are examples of other types of
stimulation techniques which have been used to increase the methane
recovery rate from a formation. These stimulations typically are
conducted in formations where the region of the wellbore
penetrating the solid carbonaceous subterranean formation is
completed with a cased hole technique, a so-called cased-hole
interval. With a cased-hole interval, the region of the wellbore
penetrating the solid carbonaceous subterranean formation is cased
and the casing is cemented in place using conventional techniques.
The stimulations use of a high viscosity fluid, such as gels or
foams, will assist in transporting proppant, if utilized, into the
formation. The proppant is injected into the formation through
perforations formed in the casing adjacent the formation. The high
viscosity fluids are injected at pressures above the parting
pressure of the formation. The injection of fluid at pressures
above parting pressure induces a new dominant fracture, or fracture
system, which is intended to better connect the formation to a
production well. The injection is continued for the desired length
of time and then ceased. The fluid preferably carries a proppant to
hold the fractures open once the injection pressure is released. In
general, the injection of the fluid is not repeated.
Unfortunately, gel and foam fracture techniques often result in
damage to the formation due to the interactions between the high
viscosity fluid and the formation matrix. Additionally,
conventional fracture techniques mainly create tensile fractures
within the formation and do not cause substantial shear failure
within the formation. It is believed by the inventors of the
present invention that the creation of shear failure within the
formation is important for enhancing the recovery of methane from a
formation. Because conventional fracture techniques do not cause
significant shear failure within the formation, they do not
significantly reduce the stress within the formation. In fact, if
proppants are utilized with conventional fracture techniques, the
proppants often increase the stress within the carbonaceous matrix.
This increase in stress can reduce the recovery of methane from the
formation by compressing the cleats and reducing the permeability
of the formation.
A third stimulation technique which has been utilized to enhance
the methane recovery rate from a formation is water fracture
treatments. Like gel fracture treatments, this technique is
typically utilized in formations in which the wellbore interval
penetrating the formation is completed with a cased-hole technique.
The treatments typically are conducted through perforations in the
casing adjacent the formation. The water is injected at a pressure
above the formation parting pressure of the formation, inducing a
new dominant fracture, or fracture system, which is intended to
better connect the formation to a production well. The technique
optionally utilizes proppants to hold the fractures open. Like gel
fracture treatments, conventional water fracture treatments
generally do not cause substantial shear failure within the
formation.
Puri et al., U.S. Pat. No. 5,014,788, discloses a method for
increasing the permeability of a coal seam by introducing a fluid
into the coal seam which causes the coal to swell. The pressurized
fluid is maintained within the seam to enhance the contact between
the fluid and the coal seam. The pressure within the seam is
relieved by allowing the fluid to flow out the wellbore prior to
the pressure within the coal seam decreasing to a stabilized
pressure. The method of the patent is intended to increase the
permeability of a coal seam located near the wellbore. The patent
teaches that the procedure may be repeated but it does not disclose
how many times to repeat the procedure or how to determine how many
repetitions are to be performed.
What is needed is a method for stimulating a solid carbonaceous
subterranean formation to increase the rate of methane recovery
from the formation which enables various fluids to be used to
stimulate the formation while minimizing the damage to the
permeability of the formation.
SUMMARY OF THE INVENTION
The present invention is a method for increasing the rate of
recovery of methane from a solid carbonaceous subterranean
formation, the method comprising:
a) introducing a first fluid into the solid carbonaceous
subterranean formation which sorbs to the solid carbonaceous
subterranean formation;
b) allowing at least a portion of the first fluid to sorb to the
solid carbonaceous subterranean formation;
c) introducing a chemically different second fluid into the solid
carbonaceous subterranean formation at a pressure higher than the
parting pressure of the solid carbonaceous subterranean
formation;
d) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean formation; and
e) repeating steps c) through d) until a desired permeability of
the solid carbonaceous subterranean formation is obtained.
In a second embodiment of the invention, a method is disclosed for
improving the recovery of methane from a solid carbonaceous
subterranean formation penetrated by a wellbore, the method
comprising the steps of:
a) introducing a fluid into the solid carbonaceous subterranean
formation which sorbs to the solid carbonaceous subterranean
formation at a pressure above the parting pressure of the
formation;
b) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean format:ion; and
c) repeating steps a) through b) until a rate of change of the
parting pressure from cycle; to subsequent cycle does not
economically justify further stimulation of the formation.
In a third embodiment of the invention, a method is disclosed for
improving the recovery of methane from a solid carbonaceous
subterranean formation penetrated by a wellbore having wellbore
control equipment, capable of regulating the rate of fluid flow
from the wellbore, the method comprising the steps of:
a) introducing a fluid into the solid carbonaceous subterranean
formation which sorbs to the solid carbonaceous subterranean
formation at a pressure above the parting pressure of the
formation;
b) relieving pressure within the solid carbonaceous subterranean
formation to produce shear failure within the solid carbonaceous
subterranean formation; and
c) repeating steps a) through b) until a rate of change of the
apparent closure pressure from cycle to subsequent cycle does not
economically justify further stimulation of the formation.
As used herein, the following terms have the following
meanings:
(a) "formation parting pressure" and "parting pressure" mean the
pressure needed to open a formation and propagate an induced
fracture through the formation.
(b) "closure pressure" is the pressure at which an induced fracture
closes. Both the parting pressure and the closure pressure of a
formation can change during the application of the invention to the
formation.
(c) "solid carbonaceous subterranean formation" refers to any
substantially solid, methane-containing material located below the
surface of the earth. It is believed that these solid,
methane-containing materials are produced by the thermal and
biogenic degradation of organic matter. Solid carbonaceous
subterranean formations include but are not limited to coalbeds and
other carbonaceous formations such as some shales.
The present invention causes substantial shear failure within the
formation and offers an improved method for stimulating a solid
carbonaceous subterranean formation to increase the recovery of
methane from production wells that penetrate the formation and are
completed using either "cased-hole" or "open-hole" completion
techniques. Also, the invention is effective in new wells or as a
workover technique for older wells.
The embodiments of the invention which utilize a first and second
fluid provide advantages that are not readily attainable by using a
single fluid. For example, the first fluid protects the
carbonaceous matrix from second fluids which may damage the matrix.
For the purposes of this invention, a "carbonaceous matrix"
includes both a carbonaceous material and the natural system of
fractures located within the material. Also, if a cold fluid is
used for either the first or second fluid, thermoelastic stresses
will be created within the formation which enhance the failure of
the matrix.
In another aspect of the invention a method is provided for
conducting an optimum stimulation technique so that time and
expenses are not wasted in the stimulation of the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a diagrammatical elevational view of a wellbore
penetrating a solid carbonaceous subterranean formation.
FIG. 2 is a graphical representation of the surface wellbore
pressure versus time as a fluid is introduced into the formation,
by injecting it through a wellbore at a pressure greater than the
formation parting pressure. The graph also shows the change in the
surface wellbore pressure as the wellbore is blown down.
FIG. 3 is a graphical representation of the formation parting
pressure versus injection/blowdown cycle number and the apparent
closure pressure versus injection/blowdown cycle number.
DETAILED DESCRIPTION OF THE INVENTION
The invention is a method of increasing the rate of recovery of
methane from a solid carbonaceous subterranean formation. The
method involves introducing into the solid carbonaceous
subterranean formation a first fluid which sorbs to the
carbonaceous matrix of the solid carbonaceous subterranean
formation. An example of a suitable first fluid is carbon dioxide.
The first fluid is maintained in the formation to allow it to sorb
to the carbonaceous matrix of the formation. Complete sorption of
the first fluid is not required. A second fluid subsequently is
introduced into the solid carbonaceous subterranean formation by
injecting it through a wellbore at a pressure higher than the
parting pressure of the formation. The injection of the second
fluid at a pressure higher than parting pressure creates a new
dominant tensile fracture or fracture system within the formation.
This may be accomplished by further opening and extending
preexisting fractures within the formation or by creating new
fractures within the formation. Preferably, the second fluid is
introduced rapidly into the formation to enhance the fracturing of
the formation.
Once the desired amount of second fluid has been injected, the
pressure within the formation is rapidly relieved through the
wellbore. This rapid relief of the pressure is called "blowdown".
Shear failure will occur within the carbonaceous matrix during
blowdown due to the rapid relief of pressure within the formation.
Factors, such as, the release of pressure within the formation, the
drag forces exerted on the carbonaceous matrix as the pressure is
relieved, and the physical changes, as discussed below, which
result from the introduction of a first and a second fluid into the
formation all enhance the shear failure within the formation.
The injection of the second fluid and the blowdown of the wellbore
is repeated several times until the desired permeability of the
formation is obtained. It is believed the increased permeability is
a result of the relief of stress within the formation and the
effects of the phenomenon of dilatancy. The phenomenon of dilatancy
causes expansion of the matrix as the stress within the formation
is reduced. This expansion of the matrix tends to be accompanied by
an increase in the porosity and permeability of the matrix.
Additionally, because the matrix of most formations is
heterogeneous, any swelling which occurs as a result of fluid
sorbing to the matrix will be uneven. The uneven swelling and
uneven shrinking of the carbonaceous matrix that may occur within
the formation as fluids are introduced and the wellbore is blown
down will induce mechanical stresses and will promote shear failure
within the formation.
The First Fluid
The first fluid can comprise any fluid which sorbs to the
carbonaceous matrix of the solid carbonaceous subterranean
formation. Preferably, cold liquid carbon dioxide is used. Carbon
dioxide is preferred because it strongly sorbs to the carbonaceous
matrix. The first fluid is injected into the solid carbonaceous
subterranean formation and then is allowed to soak within the
formation. The soak period is variable in length and may be short
enough so that the introduction of the second fluid can commence as
soon as the equipment is aligned to inject the second fluid into
the formation. During the soak period, at least a portion of the
first fluid sorbs to the carbonaceous matrix and may cause it to
swell. As discussed earlier, uneven swelling and uneven shrinking
of the matrix can promote failure within the formation.
Additionally, the use of a first fluid, such as liquid carbon
dioxide, especially if cold, will reduce the cohesion within the
carbonaceous matrix. The cohesion of the carbonaceous matrix is the
tendency of the matrix to stick together. If a large enough shear
force is applied to the matrix, it will fail. The reduction in
cohesion of the matrix by the first fluid will reduce the magnitude
of the shear force required to cause failure within the
carbonaceous matrix of the formation. This will make it easier to
cause failure within the formation. A cold first fluid will also
induce thermoelastic stresses which will promote failure within the
matrix, especially if the first fluid is colder than the matrix and
the second fluid is hotter than the matrix. Failure within the
matrix, by whatever mechanism, will be accompanied by permeability
enhancement within the formation.
The first fluid will fill up the pore spaces within the
carbonaceous matrix as it sorbs to the carbonaceous matrix. When
the pore spaces are filled with the sorbed fluid, the formation is
not as easily damaged by fluids such gels. It may be advantageous
to use high viscosity fluids such as forms or gels when it is
desirable to introduce proppants into the formation. This is
because these fluids .are viscous and able to better transport the
proppant into the formation.
In addition to filling the pore spaces of the carbonaceous matrix,
first fluids such as carbon dioxide, which are in a gaseous state
within the formation, help to expel the second fluid from the
formation. This is a result of the expansion of the gaseous first
fluid within the formation as the pressure is relieved through the
wellbore during blowdown. As the first fluid expands, it tends to
push the second fluid away from the carbonaceous matrix. This will
result in better cleanup of the formation with less chance of
residues from the second fluid damaging the formation. Also, as the
second fluid flows back toward the wellbore, shear forces are
created within the formation which enhance the failure within the
formation.
The Second Fluid
As discussed earlier, the second fluid is injected into the solid
carbonaceous subterranean formation after the first fluid has
soaked within the formation for a sufficient period of time. The
second fluid should be injected at a pressure higher than the
parting pressure of the formation.
It is believed that a violent and rapid pressurization and
depressurization of the formation is important in obtaining the
maximum stress relief within the carbonaceous matrix of the solid
carbonaceous subterranean formation. Water, foams, or gels can be
used to achieve the maximum stress relief within the formation.
Water and other relatively incompressible fluids will allow
pressure to be built up rapidly within the formation and to be
rapidly released during blowdown. These fluids will also exert drag
forces on the carbonaceous matrix during blowdown. The application
of drag forces to the carbonaceous matrix during blowdown will
further aid in the failure of the formation.
Gaseous fluids such as air, carbon dioxide, nitrogen, argon,
hydrogen, methane, flue gas, helium or combinations thereof are
preferably utilized as the second fluid in selected applications of
the invention, such as where there is concern that the use of a
liquid may damage the permeability of the formation.
In some situations, it may be advantageous to use only a single
fluid to stimulate a formation. In this type of situation, the
fluid is injected into the formation at a pressure greater than the
parting pressure of the formation. The injection of fluid and the
subsequent blowdown of the formation is repeated until a desired
permeability is obtained within the formation. In this aspect of
the invention it can be advantageous to inject a relatively cold
fluid intermittently between injections of warmer fluid.
Alternatively, the injection of colder and warmer fluids can be
alternated. By alternating the cold and warmer fluid, thermoelastic
stresses within the formation may be increased which will enhance
the shear failure within the formation. It may be preferable to
minimize the time between injection and blowdown cycles to maximize
the thermoelastic stress differentials within the formation.
The methods for determining when to stop repeating the injection
and blowdown steps with either a single fluid or multiple fluids
are discussed more fully below.
Operation
Referring to FIG. 1, in a preferred embodiment of the invention, a
first fluid, such as carbon dioxide, is introduced into a solid
carbonaceous subterranean formation 11 through a wellbore 13. The
portion of the wellbore 13 which penetrates the carbonaceous
formation 15 may be cased or completed using an open-hole
technique. If the well is completed using an open-hole technique,
it can be advantageous to score the carbonaceous matrix in the
region surrounding the wellbore prior to performing the method of
the current invention. Alternatively, the walls of the open-hole
interval can be cut to produce a square shape within the formation
as viewed from above, or some other shape which will intensify the
stresses acting on the open-hole interval. The focusing of the
stresses acting on the open-hole interval which results from either
scoring the walls or cutting them into a predetermined shape will
assist in the failure of the carbonaceous matrix.
The first fluid may be injected below or above the parting pressure
of the formation. In determining whether to inject the first fluid
at a pressure above or below the parting pressure, it is important
to consider what the second fluid will be and whether the
associated stimulation technique is to be directed mainly to the
wellbore area or to the formation in general. An example of a
situation where it can be important to inject the first fluid at
above the parting pressure is when a cross-linked gel is to be used
for the second fluid. In this instance, the injection of the first
fluid above the parting pressure of the formation will force the
first fluid into the formation beyond the near wellbore region. The
first fluid will fill up the pore spaces of the carbonaceous matrix
beyond the wellbore region and should minimize any potential damage
to the permeability of the formation caused by sorption of the
second fluid to the matrix beyond the wellbore region.
It may be desirable to repeat the injection of first fluid, either
intermittently, or alternatively, before each injection of second
fluid. The introduction of first fluid more than once during the
procedure may assist in the failure of the carbonaceous matrix,
especially if a cold fluid, such as liquid carbon dioxide, is used
as the first fluid. Also, injecting the first fluid into the
formation more than once may help to minimize potential damage to
the formation by second fluid.
Referring now to FIG. 2, illustrated is a plot of the surface
wellbore pressure versus time during the introduction of a fluid
into the formation at greater than the parting pressure of the
formation. FIG. 2 displays the typical response of the wellbore to
the introduction and blowdown of the second fluid, or first fluid,
if only one fluid is used. The surface wellbore pressure is plotted
because it is a readily measurable parameter and because it is
equivalent to the wellbore pressure near the formation in our
present invention. Line segment 17 shows the surface wellbore
pressure increasing during initial filling and pressurization of
the wellbore. The pressure within the wellbore increases until it
reaches the parting pressure 19 of the formation. Induced fractures
within the formation are extended after the pressure in the
wellbore reaches the parting pressure 19 of the formation. During
the extension of the fracture system, the wellbore pressure may
remain approximately constant as shown by line segment 21 or it may
decrease. It may be preferable to minimize the duration of each
injection portion of the cycle after parting pressure has been
exceeded in order to minimize the amount of fluid utilized.
After injection of the fluid has ceased, blowdown of the formation
is initiated by rapidly relieving pressure within the formation by
venting through the wellbore. As shown in FIG. 2, during the
blowdown period, which includes segments 23 and 24, the surface
wellbore pressure initially decreases at a rate depicted by segment
23 until the apparent closure pressure 25 of the formation is
reached. The apparent closure pressure 25 is the pressure measured
at the wellbore when the majority of the induced fractures have
closed. The apparent closure pressure 25 is used because stress
varies within the formation relative to the distance from the
wellbore and because the closure pressure may not be the same for
all points within the formation. As can be seen from FIG. 2, when
the apparent closure pressure 25 is reached, the rate of change of
surface wellbore pressure decreases. Segment 24 depicts the rate of
change in the surface wellbore pressure after the apparent closure
pressure 25 is reached. The exact rate of change of the pressure is
not critical for the current invention. What is useful to the
current invention is the understanding that it may be possible to
determine the apparent closure pressure of the formation by an
inspection of a plot of surface wellbore pressure versus time
during blowdown.
As pressure is relieved and the fluids move towards the wellbore,
the rapid release of pressure and the drag forces exerted on the
carbonaceous matrix will cause failure within the carbonaceous
matrix and the release of fines from the carbonaceous matrix into
the wellbore region. It is preferable to relieve the pressure at
the maximum rate attainable. The maximum rate attainable is the
rate which results from flowing back the fluids through the
wellbore and wellbore control equipment with no added flow
restriction that is not required for safely practicing the
invention. More preferably, the pressure within the formation is
relieved from at least 100 to 1000 p.s.i. above the formation
parting pressure to 200 to 600 p.s.i. below the reservoir pressure
of the formation within about 15 minutes to one hour.
If the wellbore was completed using cased-hole techniques, new
perforations should preferably be created in the casing near the
formation prior to blowdown of the formation. A casing gun is
preferably used when perforating the casing. Other alternatives
techniques which may be used to perforate the casing include
overbalanced perforating and/or the creation of slots in the casing
by fluid jetting apparatus. The new holes created in the casing
will aid in the removal of fines from the region surrounding the
wellbore. The removal of the fines will assist in further failure
of the formation and will reduce potential near wellbore
permeability damage caused by fines. Fines which flow into the
wellbore but are not removed to the surface during blowdown can be
collected in a rathole which preferably is formed at the bottom of
the wellbore. A pump can be installed in the rathole to aid in the
removal of fines and fluids from the wellbore.
The rapid introduction of second fluid above the formation parting
pressure and blowdown of the formation is repeated until the
desired degree of failure within the formation is obtained. If a
single fluid is used it is repeatedly introduced at a pressure
above the formation parting pressure and the formation is
repeatedly blown down through the wellbore.
In one aspect of the invention, the injection and blowdown are
repeated until the amount of fines produced after the injection and
blowdown cycle is reduced to near zero. In another aspect of the
invention, parting pressure for each cycle is determined from a
plot of surface wellbore pressure versus time for the
pressurization portion of the cycle, such as depicted in FIG. 2.
The parting pressures for each cycle are then plotted as depicted
in FIG. 3. The parting pressure should decrease with every
subsequent injection and blowdown cycle. While not wishing to be
bound by any theory, it appears that this results because the
parting pressure is proportional to the in situ stress within the
solid carbonaceous subterranean formation. As the stress is
relieved within the solid carbonaceous subterranean formation, the
parting pressure will decrease. The injection and blowdown cycle
should be repeated until the rate of change of the parting pressure
from cycle to subsequent cycle does not economically justify
further stimulation of the formation. Preferably, the injection and
blowdown cycle should be repeated until a calculated rate of change
of the parting pressure from the second to last introduction of
fluid to the last introduction of fluid is less than one-half the
calculated rate of change of the parting pressure from the third to
the last introduction of fluid to the second to last introduction
of fluid. More preferably, the injection and blowdown cycle should
be repeated until the rate of change of the parting pressure from
cycle to subsequent cycle approaches a value of near zero (i.e. the
parting pressure approaches an approximately constant value on
successive cycles.)
In a further aspect of the invention, the apparent closure pressure
for each cycle is determined from a plot of surface pressure
wellbore versus time for the blowdown portion of the cycle, such as
depicted in FIG. 2. The apparent closure pressures for each cycle
are then plotted as depicted in FIG. 3. The apparent closure
pressure, like the parting pressure, should decrease with every
subsequent injection and blowdown cycle. The cycle of injection and
blowdown should be repeated until the rate of change of the
apparent closure pressure from cycle to subsequent cycle does not
economically justify further stimulation of the formation.
Preferably, the injection and blowdown cycle should be repeated
until a calculated rate of change of the apparent closure pressure
from the second to last introduction of fluid to the last
introduction of fluid is less than one-half the calculated rate of
change of the apparent closure pressure from the third to the last
introduction of fluid to the second to last introduction of fluid.
More preferably, the injection and blowdown cycle should be
repeated until the rate of change of the apparent closure pressure
from cycle to subsequent cycle approaches a value of near zero
(i.e. the apparent closure pressure approaches an approximately
constant value on successive cycles.)
From the foregoing description, it can be observed that numerous
variations, alternatives and modifications will be apparent to
those skilled in the art. Accordingly, this description is to be
construed as illustrative only and is for the purpose of teaching
those skilled in the art the manner of carrying out the invention.
Thus, it will be appreciated that various modifications,
alternatives, variations, etc., may be made without departing from
the spirit and scope of the invention as defined in the appended
claims. It is, of course, intended that the appended claims cover
all such modifications involved within the scope of the claims.
* * * * *